CNL-14-221, Response to NRC Request for Additional Information Regarding Review of License Renewal Application, Set 23, B.1.34-9.d (Follow Up)

Response to NRC Request for Additional Information Regarding Review of License Renewal Application, Set 23, B.1.34-9.d (Follow Up)

ML14350A683
Person / Time
Site:	Sequoyah
Issue date:	12/11/2014
From:	James Shea Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNL-14-221, TAC MF0481, TAC MF0482
Download: ML14350A683 (40)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 CNL-14-221 December 11, 2014 10 CFR Part 54 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2 Facility Operating License Nos. DPR-77 and DPR-79 NRC Docket Nos. 50-327 and 50-328

Subject:

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 23, B.1.34-9.d (Follow up) (TAC Nos. MF0481 and MF0482)

References:

1. TVA Letter to NRC, Sequoyah Nuclear Plant, Units 1 and 2 License Renewal, dated January 7, 2013 (ADAMS Accession No. ML13024A004)

2. NRC Letter to TVA, Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application

- Set 23, dated December 4, 2014 By letter dated January 7, 2013 (Reference 1), the Tennessee Valley Authority (TVA) submitted an application to the Nuclear Regulatory Commission (NRC) to renew the operating licenses for the Sequoyah Nuclear Plant (SQN), Units 1 and 2. The request would extend the licenses for an additional 20 years beyond the current expiration dates.

By Reference 2, the NRC forwarded request for additional information (RAI) B.1.34-9.d (Follow up) with a response due date no later than January 4, 2015. Enclosure 1 contains TVAs response to RAI B.1.34-9.d (Follow up).

Consistent with the standards set forth in 10 CFR 50.92(c), TVA has determined that the additional information, as provided in this letter, does not affect the no significant hazards considerations associated with the proposed application previously provided in Reference 1.

ENCLOSURE 1 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal TVA Response to NRC RAI B.1.34-9.c (Follow up)

RAI B.1.34-9.d (Follow up) [Reference 1]

Background:

By letter dated October 22, 2014, [Reference 2] the applicant provided its response to the staffs Request for Additional Information (RAI) B.1.34-9c related to the applicants plant specific fluence evaluations for the upper core plates at Sequoyah (SQN) Units 1 and 2 for the components that are located above the upper core plates. This response included the methodology used to perform these evaluations as well as the projected fluence values for the upper core plate and above the upper core plate.

Additional background information for Part 1 of this RAI: As stated in the response, the discussion on fluence methodology beginning on Page 2 of Enclosure 1 to the response letter indicates that the transport methods described in WCAP-14040-A, and WCAP-16083-NP-A were used to calculate fluence values for locations above the upper core plate. The response indicates that the (r,z) transport model was updated to include information specific to regions directly above the active fuel stack for SQN-1.

Additional background information for Part 2 of this RAI: As stated in the response, the discussion on upper core plate neutron fluence values, beginning on Page 3 of Enclosure 1 to the response letter, indicates that the fluence value is 1.87E21 n/cm2 for the lower surface of the upper core plat for SQN Unit 1. Note that reactor vessel fluence methods are permitted a 20- percent margin for accuracy because the formulae for performing adjusted reference temperature (ART) margin term adjustments include 20-percent margins for the fluence terms used in the ART calculations.

Issue:

The fluence calculations provided by the applicant in its letter of October 22, 2014, provide the projected fluence values for SQN Units 1 and 2, but do not provide specific locations for the reported values, nor the projected values include any uncertainty or margin of accuracy, nor if the chosen methodology is qualified for estimating fluence values at the upper core plate location.

Request:

1. For SQN Units 1 and 2:

(a) Indicate the radial location of the peak estimated fluence values for the upper core plate.

(b) Provide graphics to compare the prior and current (r,z) models.

(c) Show that the current (r,z) spatial representation is sufficiently refined.

(d) Provide information to verify that the detail represented in the (r,) model is adequate and produces a reliable fluence estimate. Specifically, Regulatory Guide (RG) 1.190 permits representation of internal fuel assemblies in considerably less detail than peripheral assemblies, particularly because the contribution of fuel, at the core E1 - 1 of 8

periphery, to the vessel flux is most significant. This is not the case for the upper core plate.

(e) Provide information to indicate that the chosen fluence methods are qualified for estimating fluence at the upper core plate location.

2. For SQN Unit 1: explain whether the neutron fluence value reported for the lower surface of the upper core plate of SQN Unit 1 (i.e., 1.87 x 1017 n/cm2 [E > 1.0 MeV]) has been augmented to account for any uncertainty associated with the calculative methods, nuclear data, or modeling accuracy.

TVA Response to RAI B.1.34-9.d (Follow up)

1. For SQN Units 1 and 2:

In accordance with the Materials Reliability Program (MRP) 2013-025 (Reference 3), an evaluation using an appropriate radiation transport methodology was performed to determine whether the areas above the SQN upper core plates (UCPs) would exceed the irradiation embrittlement (IE) threshold of 1021 n/cm2 [E > 1.0 MeV] threshold after 60 years of operation. Such an evaluation typically utilizes either the synthesis methodology (which combines the r-, rz-, and r- geometry solutions to achieve a synthesized three-dimensional (3-D) flux distribution), or, if needed, a full 3-D geometry radiation transport analysis. Because a detailed, rigorous neutron exposure data throughout the UCP (i.e., a 3-D map: radial, axial, and azimuthal) was not necessary, the synthesis methodology was deemed to be appropriate for these evaluations. Although the original intent of the evaluation did not include the calculation of absolute maximum fluence at the lower and upper surface of the UCP, these specific values were provided in Reference 2 as requested in RAI B.1.34-9c.

(a) The radial locations of the estimated maximum fluence values are 75 cm from the core centerline for both surfaces of the UCP at SQN Unit 1 and 50 cm for both surfaces of the UCP at SQN Unit 2.

(b) The modifications to the SQN Unit 1 rz- geometry model from the prior model included:

Placement of the bottom surface of the UCP to match the expected lifetime-average distance between the top of the active fuel and the lower surface of the UCP, and Substitution of the material in the annular axial blanket region at the top of the active fuel with solid pellet material.

Because the rz- geometry plot extends radially from the core centerline to a location interior to the primary biological shield and over an axial span from an elevation approximately six feet below the active fuel to five feet above the active fuel, the only modification that would be evident by comparing the rz- geometry plot from the time-limited aging analysis (Reference 4) to the rz- geometry plot with the updated data is the change of the material in the annular axial blanket region at the top of the active fuel. This material would appear as a different E1 - 2 of 8

color in the plots. As discussed with the NRC staff on November 18, 2014, graphical plots are not useful in this application.

(c) The axial mesh spacing in the rz model is approximately 0.9 inch in the fuel plenum / end plug region directly above the active fuel region, approximately 0.6 inch in the top nozzle region, and approximately 0.5 inch within the UCP. For the purpose of this evaluation, the axial mesh spacing provides sufficient accuracy to determine the neutron exposure for the materials that are located directly above the active fuel region.

(d) Regulatory Guide 1.190 (Reference 5) prescribes that the radial power gradients in the peripheral fuel assemblies need to be considered in constructing the spatial power distribution in those assemblies, as the peripheral assemblies contribute the most to vessel fluence.

For regions located axially above the active fuel, equivalent data that would provide axial power gradients at the top of each fuel assembly are not readily available from the core designers. Also, there are no specific acceptance criteria for the neutron exposure evaluation of reactor internals. Therefore, the construction of a more detailed spatial axial power distribution at the top of each fuel assembly is not performed for this analysis.

(e) There is limited measurement data available for reactor internals with which to compare calculated values. The VENUS PWR engineering mockup benchmark experiment (Reference 6) provides measured data in the radial internals (baffle plates and core barrel) for comparison with calculated results (References 7 and 8). Calculated values agreed to within 10% of measured values. More recently, as part of a testing program for cladding material, test samples were irradiated in the core and also in the regions above the core. Dosimetry analysis of the activated cladding samples was performed and compared with Westinghouse calculations (Reference 9). The measured-to-calculated reaction rate ratios ranged from 0.82 to 2.12. Although not inside the pressure vessel, the ex-vessel neutron dosimetry gradient chains, which extend beyond the elevation of the active fuel region, have been analyzed using the Westinghouse synthesis and 3 D methodologies at numerous plants. The calculated reaction rates typically agree well with the measured reaction rates.

The comparisons performed to date demonstrate that the methodology is appropriate to estimate the neutron exposure of reactor internals components.

2. The estimated fluence values are best estimate values which have no extrinsically applied factors to increase (or decrease) the values.

Plant-specific fluence evaluations were undertaken for both SQN Unit 1 and SQN Unit 2 because the Units did not meet the MRP 2013-025 (Reference 3) minimum E1 - 3 of 8

requirement for spacing between the active core and the UCP. The plant-specific evaluations successfully demonstrated that the projected 60-year fluence on the top or non-core side surface of the UCP in both units is below the 1x1021 n/cm2 [E > 1 MeV]

((or 1.5 displacements per atom (dpa)) screening fluence threshold for IE.

Appendix F of MRP-175 (Reference 10) describes the original technical basis for the IE screening fluence threshold. The MRP-175 analysis concluded that there was a reasonable database available to establish a screening fluence threshold of 5 dpa.

However, final recommendation was that for added assurance in performing the screening, 30% of the 5 dpa value (or 1.5 dpa) is suggested. There is sufficient margin in the screening fluence threshold value to account for uncertainty in the fluence determination and distribution. Therefore, additional margin for uncertainty in the neutron fluence on the top surface of the UCP is not necessary.

Although the analysis indicates that the UCP may be subject to IE, the results indicate that the peak UCP fluence is below the screening limit for irradiation-assisted stress corrosion cracking (IASCC). MRP-175 sets a lower limit screening dose of 2x1021 n/cm2 [E > 1 MeV] (or 3 dpa) for IASCC. MRP-175 states that this lower limit screening dose is to be utilized for highly stressed component items such as bolts, springs, and multi-pass welds. The maximum projected fast neutron fluence near the bottom surface of the UCP over 60 years of operation is estimated to be 1.87x1021 and 1.82x1021 n/cm2 [E > 1 mega electron volts (MeV)] for SQN Unit 1 and SQN Unit 2 respectively (Reference 11). Both of these estimated values fall below the screening fluence for highly stressed components. The application of this lower limit, high stress screening dose to the UCP is a conservative assumption noting that the UCP is not a bolt or spring and does not contain multi-pass structural welds. For components with higher fluences, the MRP-175 screening criteria provide a fluence-stress based screening criteria that allows stresses up to 89 kips per square inch ((616 mega Pascal (MPa)) below 6.7x1021 n/cm2 [E > 1 MeV] (or 10 dpa).

Consideration of more realistic UCP stresses significantly increases the screening fluence for IASCC in this component. There is sufficient margin in the screening values applied to account for any uncertainty associated with the calculative methods, nuclear data, or modeling. Given its higher dose threshold and the large stresses required to initiate cracking, IASCC is not considered a credible damage mechanism in the UCP for the SQN Units. Therefore, there is no need to augment the fluence estimates on the bottom surface of the UCP to evaluate IASCC susceptibility.

Impact of UCP Irradiation Embrittlement on MRP-227-A Sampling Inspection Program The range of conditions considered in the sensitivity study became the basis for the MRP-227-A (Reference 12) applicability guidelines defined in MRP 2013-025 (Reference 3). Although the results of the sensitivity study indicate that some plants may have portions of the UCPs with fluences above the IE screening threshold, there is minimal impact on the MRP-227-A screening criteria for the following reasons:

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1. The screening process was intended to identify the potential onset of aging degradation.

2. The identification of IE for these components is marginal; there are many other components in the MRP-227-A inspection plan with significantly higher fluences, including the baffle/former structure, core barrel and lower core plate.

3. There are no irradiation-related cracking mechanisms identified for the UCP; therefore, there is no increase in the probability of crack initiation.

4. There are no available non-destructive techniques to detect the level of embrittlement. Any flaw evaluation would be based on bounding toughness curves from laboratory data, not inspection.

There is no need for any new entries to the MRP-227-A inspection tables for SQN Unit 1 or SQN Unit 2 because the UCP is already listed as an expansion inspection component. Based on the fluence sensitivity studies, it would be appropriate to include loss of toughness due to IE as an aging effect being managed by the inspection of the UCP.

The MRP-227-A expansion inspection of the Westinghouse UCP is triggered by the observation of cracking in the control rod guide tube lower flange weld. This linkage is based on the assumption that the irradiation level in the UCP is not a concern. If IE of the UCP is a concern, the UCP should be included in the strategy for the inspection of irradiated plate materials. Although the lower core plate (LCP) has a higher projected fluence and is similar in both material and geometry, it is not currently identified as a primary inspection component. The LCP is included in the MRP-227-A as an existing inspection component because a VT-3 examination was deemed adequate and the upper or core side surface of the LCP is an accessible part of the core support structure, making an ASME Section XI examination suitable for managing the potential aging effect. TVA has indicated (Reference 2) that the UCP will be included in the scope of the ASME Section XI program. Following this logic, including an UCP ASME Section XI VT-3 examination of the higher fluence core side surface provides a suitable inspection for managing potential aging effects.

Based on the results of MRP 2013-025, it is anticipated that future revisions of MRP-227 will include IE in the UCP as a degradation mechanism resulting in potential aging effects. Any changes in the inspection requirement or primary to expansion linkages in the revised version of MRP-227 would be implemented at TVA under the NEI-03-08 (Reference 13) protocol. In the interim, TVA will identify the observation of cracking in the lower core barrel girth weld as the primary trigger for the EVT-1 expansion inspection of the UCP. Commitment 27.E has been added to to capture this as a commitment. Using the EVT-1 inspection of the lower core barrel girth weld as the link for further inspection of the UCP will provide a high degree of conservatism and added margin for managing the effects of aging.

The higher irradiation levels and large residual stresses make initiation of cracking in the core barrel far more likely than cracking in the UCP.

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References

1. NRC Letter to TVA, Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application - Set 23 (TAC Nos. MF0481 and MF0482), December 4, 2014.

2. TVA Letter, CNL-14-181, Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 22, B.1.34-9c (TAC Nos. MF0481 and MF0482),

October 22, 2014.

3. Materials Reliability Program: MRP-227-A Applicability Template Guideline (MRP 2013-025), EPRI. Palo Alto, CA, October 14, 2013.

4. Westinghouse Report, WCAP-17539-NP, Rev. 0, Sequoyah Units 1 and 2 Time-Limited Aging Analysis on Reactor Vessel Integrity, March 2012.

5. U.S. NRC Regulatory Guide 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence, March 2001.

6. Nuclear Energy Agency Organization for Economic Co-Operation and Development, Prediction of Neutron Embrittlement in the Reactor Vessel:

VENUS-1 and VENUS-3 Benchmarks, 2000.

7. Westinghouse Report, WCAP-11173 (NUREG/CR-4827), Rev. 0, Neutron and Gamma-Ray Flux Calculations for the Venus PWR Engineering Mockup, January 1987.

8. A. H. Fero and E. T. Hayes, Analysis of the VENUS Benchmark Using TORT and BUGLE-96, 11th International Symposium on Reactor Dosimetry, Brussels, Belgium, August 18-23, 2002.

9. B. W. Amiri, J. P. Foster, and L. R. Greenwood, Dosimetry Evaluation of In-Core and Above-Core Zirconium Alloy Samples in a PWR, 15th International Symposium on Reactor Dosimetry, Aix-En-Provence, France, May 18-23, 2014.

10. Materials Reliability Program: PWR Internals Material Aging Degradation Mechanism Screening and Threshold Values (MRP-175). EPRI, Palo Alto, CA:

2005.

11. Westinghouse Calculation Note, CN-REA-14-24, Rev. 1, Sequoyah Units 1 and 2 Evaluation for Application of MRP-227-A Internals Inspection Plan, October 17, 2014 (Proprietary).

12. Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227-A). EPRI, Palo Alto, CA: 2011.

13. Nuclear Energy Institute Guideline, NEI 03-08, Rev. 2, Guideline for the Management of Materials Issues, January 2010.

14. U.S. NRC Letter, Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application - Set 18 E1 - 6 of 8

(TAC Nos. MF0481 and MF0482), December 6, 2013. (NRC ADAMS Accession No. ML13323A097)

15. TVA Letter, Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, B.1.34-9b, Ten Commitment Updates, and 3.0.3-1 Item 5b (TAC Nos. MF0481 and MF0482), August 21, 2014.

16. U.S. NRC Letter, Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application - Set 22 (TAC Nos. MF0481 and MF0482), September 22, 2014. (NRC ADAMS Accession No. ML14254A204)

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Changes to LRA Tables follow with additions underlined and deletions lined through.

Table C-1 Primary Components at SQN Units 1 and 2 Expansion Link Examination Method/

Item Applicability Effect (Mechanism) (Note 1) Frequency (Note 1) Examination Coverage Core barrel assembly SQN Units 1 and Cracking (SCC, Upper and lower Periodic enhanced visual (EVT- 100% of one side of the

• Upper and lower 2 irradiation-assisted core barrel cylinder 1) examination no later than two accessible surfaces of the core barrel cylinder stress corrosion axial welds refueling outages from the selected weld and adjacent girth welds cracking [IASCC], Upper core plate beginning of the license renewal base metal.

fatigue) period and subsequent (Note 4) examination on a ten-year interval.

Table C-2 Expansion Components at SQN Units 1 and 2 Item Applicability Effect (Mechanism) Primary Link Examination Method/ Examination Coverage (Note 1) Frequency (Note 1)

Upper internals assembly SQN Units 1 and Cracking (fatigue, CRGT lower Enhanced visual (EVT-1) 100% of the accessible

• Upper core plate 2 wear) flange weld examination. surfaces bottom surface of Aging Management Re-inspection every 10 years the upper core plate.

(IE) following initial inspection. (Note 2)

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ENCLOSURE 2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal Regulatory Commitment List, Revision 19 Commitment Change:

Deleted: 18.A.4, 31.G (last bullet), 37.G New: 27.E Commitments 31.G (last bullet), and 37.G have been deleted for clarity; 37.G is deleted because it is redundant with commitments A through F; 18.A.4 and 27.E changes are discussed in the cover letter; commitment 27.E is also discussed in Enclosure 1.

Changes in the highlighted commitment list are with additions underlined and deletions lined through.

A. This list supersedes all previous versions. The final version will be included in the SQN UFSAR Supplement (LRA Appendix A,) before incorporation into the SQN UFSAR (after NRC approval of the SQN LRA). After incorporation into the SQN UFSAR, changes to information within the UFSAR Supplement (such as LR commitment) will be made in accordance with 10 CFR 50.59.

B. Throughout this document, the phrase prior to entering the PEO means the SQN AMPs will be implemented six months prior to the PEO (For SQN1: prior to 03/17/20; for SQN2: prior to 03/15/21) or the end of the last refueling outage prior to each unit entering the PEO, whichever occurs later.

SQN shall notify the NRC in writing within 30 days after having accomplished items listed in the LR Commitment List and include the status of those activities that have been or remain to be completed [ML14057A808, E-1 p40, A.1-2]

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 1 A. Implement the Aboveground Metallic Tanks Program as SQN1: Prior to 03/17/20 B.1.1 described in LRA Section B.1.1. [3.0.3-1, Requests 3, SQN2: Prior to 03/15/21 ML13312A005.11/4/13]

B. Aboveground Metallic Tanks Program includes outdoor tanks on soil or concrete and indoor large volume water tanks (excluding the fire water storage tanks) situated on concrete that are designed for internal pressures approximating atmospheric pressure. Periodic external visual and surface examinations are sufficient to monitor degradation. Internal visual and surface examinations are conducted in conjunction with measuring the thickness of the tank bottoms to ensure that significant degradation is not occurring and that the components intended function is maintained during the PEO.

Internal inspections are conducted whenever the tank is drained, with a minimum frequency of at least once every 10 years, beginning in the 6-year interval prior to the PEO. [3.0.3-1 item 5a, ML13294A462, E 4 of 8, 10/17/13]

2 A. Revise Bolting Integrity Program procedures to ensure the SQN1: Prior to 03/17/20 B.1.2 actual yield strength of replacement or newly procured bolts will be SQN2: Prior to 03/15/21 less than 150 ksi B. Revise Bolting Integrity Program procedures to include the additional guidance and recommendations of EPRI NP-5769 for replacement of ASME pressure-retaining bolts and the guidance provided in EPRI TR-104213 for the replacement of other pressure-retaining bolts.

C. Revise Bolting Integrity Program procedures to specify a corrosion inspection and a check-off for the transfer tube isolation valve flange bolts.

D. Revise Bolting Integrity Program procedures to visually inspect a representative sample of normally submerged ERCW system bolts at least once every 5 years. (ML13252A036, Enc 1, B.1.2-2a, p20) 3 A. Implement the Buried and Underground Piping and Tanks SQN1: Prior to 03/17/20 B.1.4 Inspection Program as described in LRA Section B.1.4. SQN2: Prior to 03/15/21 B. Cathodic protection will be provided based on the guidance of NUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.

[B.1.4-4b, ML13252A036. E2 -4 of 7, 9/3/13]

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 4 A. Revise Compressed Air Monitoring Program procedures to SQN1: Prior to 03/17/20 B.1.5 include the standby diesel generator (DG) starting air subsystem. SQN2: Prior to 03/15/21 B. Revise Compressed Air Monitoring Program procedures to include maintaining moisture and other contaminants below specified limits in the standby DG starting air subsystem.

C. Revise Compressed Air Monitoring Program procedures to apply a consideration of the guidance of ASME OM-S/G-1998, Part 17; EPRI NP-7079; and EPRI TR-108147 to the limits specified for the air system contaminants D. Revise Compressed Air Monitoring Program procedures to maintain moisture, particulate size, and particulate quantity below acceptable limits in the standby DG starting air subsystem to mitigate loss of material.

E. Revise Compressed Air Monitoring Program procedures to include periodic and opportunistic visual inspections of surface conditions consistent with frequencies described in ASME O/M-SG-1998, Part 17 of accessible internal surfaces such as compressors, dryers, after-coolers, and filter boxes of the following compressed air systems:

Diesel starting air subsystem Auxiliary controlled air subsystem Nonsafety-related controlled air subsystem F. Revise Compressed Air Monitoring Program procedures to monitor and trend moisture content in the standby DG starting air subsystem.

G. Revise Compressed Air Monitoring Program procedures to include consideration of the guidance for acceptance criteria in ASME OM-S/G-1998, Part 17, EPRI NP-7079; and EPRI TR-108147.

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQN1: Prior to 03/17/20 B.1.8 and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 03/15/21 B. Revise Diesel Fuel Monitoring Program procedures to monitor and trend levels of microbiological organisms in the seven-day storage tanks.

C. Revise Diesel Fuel Monitoring Program procedures to include a ten-year periodic cleaning and internal visual inspection of the standby DG diesel fuel oil day tanks and high pressure fire protection (HPFP) diesel fuel oil storage tank. These cleanings and internal inspections will be performed at least once during the ten-year period prior to the period of extended operation (PEO) and at succeeding ten-year intervals. If visual inspection is not possible, a volumetric inspection will be performed.

D. Revise Diesel Fuel Monitoring Program procedures to include a volumetric examination of affected areas of the diesel fuel oil tanks, if evidence of degradation is observed during visual inspection. The scope of this enhancement includes the standby DG seven-day fuel oil storage tanks, standby DG fuel oil day tanks, and HPFP diesel fuel oil storage tank and is applicable to the inspections performed during the ten-year period prior to the PEO and succeeding ten-year intervals.

6 A. Revise External Surfaces Monitoring Program procedures to SQN1: Prior to 03/17/20 B.1.10 clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 03/15/21 aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).

B. Revise External Surfaces Monitoring Program procedures to include instructions to look for the following related to metallic components:

Corrosion and material wastage (loss of material).

Leakage from or onto external surfaces loss of material).

Worn, flaking, or oxide-coated surfaces (loss of material).

Corrosion stains on thermal insulation (loss of material).

Protective coating degradation (cracking, flaking, and blistering).

Leakage for detection of cracks on the external surfaces of stainless steel components exposed to an air environment containing halides.

C. Revise External Surfaces Monitoring Program procedures to include instructions for monitoring aging effects for flexible polymeric components, including manual or physical manipulations of the material, with a sample size for manipulation of at least E 4 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (6) ten percent of the available surface area. The inspection parameters for polymers shall include the following:

Surface cracking, crazing, scuffing, dimensional changes (e.g.,

ballooning and necking).

Discoloration.

Exposure of internal reinforcement for reinforced elastomers (loss of material).

Hardening as evidenced by loss of suppleness during manipulation where the component and material can be manipulated.

D. Revise External Surfaces Monitoring Program procedures to specify the following for insulated components.

Periodic representative inspections are conducted during each 10-year period during the PEO.

For a representative sample of outdoor components, except tanks, and indoor components, except tanks, identified with more than nominal degradation on the exterior of the component, insulation is removed for visual inspection of the component surface. Inspections include a minimum of 20 percent of the in-scope piping length for each material type (e.g.,

steel, stainless steel, copper alloy, aluminum). For components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of the surface area is inspected. Inspected components are 20% of the population of each material type with a maximum of 25.

Alternatively, insulation is removed and component inspections performed for any combination of a minimum of 25 1-foot axial length sections and individual components for each material type (e.g., steel, stainless steel, copper alloy, aluminum.)

For a representative sample of indoor components, except tanks, operated below the dew point, which have not been identified with more than nominal degradation on the exterior of the component, the insulation exterior surface or jacketing is inspected. These visual inspections verify that the jacketing and insulation is in good condition. The number of representative jacketing inspections will be at least 50 during each 10-year period.

If the inspection determines there are gaps in the insulation or damage to the jacketing that would allow moisture to get behind the insulation, then removal of the insulation is required to inspect the component surface for degradation.

For a representative sample of indoor insulated tanks operated below the dew point and all insulated outdoor tanks, insulation is removed from either 25 1-square foot sections or 20 percent of the surface area for inspections of the exterior surface of each tank. The sample inspection points are distributed so that inspections occur on the tank dome, sides, near the bottom, at points where structural supports or instrument nozzles penetrate the insulation, and where water collects (for example on top of stiffening rings).

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (6) Inspection locations are based on the likelihood of corrosion under insulation (CUI). For example, CUI is more likely for components experiencing alternate wetting and drying in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point.

If tightly adhering insulation is installed, this insulation should be impermeable to moisture and there should be no evidence of damage to the moisture barrier. Given that the likelihood of CUI is low for tightly adhering insulation, a minimal number of inspections of the external moisture barrier of this type of insulation, although not zero, will be credited toward the sample population.

Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection.

• No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction

• No evidence of cracking Nominal degradation is defined as no loss of material due to general, pitting, or crevice corrosion, beyond that which could have been present during initial construction, and no evidence of cracking. If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g. water seepage through insulation seams/joints), periodic inspections under the insulation will continue as described above.

[3.0.3-1 Request 6a, ML13357A722, E 24 of 43, 12/16/13]

E. Revise External Surfaces Monitoring Program procedures to include acceptance criteria. Examples include the following:

Stainless steel should have a clean shiny surface with no discoloration.

Other metals should not have any abnormal surface indications.

Flexible polymers should have a uniform surface texture and color with no cracks and no unanticipated dimensional change, no abnormal surface with the material in an as-new condition with respect to hardness, flexibility, physical dimensions, and color.

Rigid polymers should have no erosion, cracking, checking or chalks.

F. For a representative sample of outdoor insulated components and indoor insulated components operated below the dew point, which have been identified with more than nominal degradation on the exterior of the component, insulation is removed for inspection of the component surface. For a representative sample of indoor insulated E 6 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (6) components operated below the dew point, which have not been identified with more than nominal degradation on the exterior of the component, the insulation exterior surface is inspected. These inspections will be conducted during each 10-year period during the PEO. [3.0.3-1 Request 6a, ML13357A722, E 23 of 43, 12/16/13]

G. Specific, measurable, actionable/attainable and relevant acceptance criteria are established in the maintenance and surveillance procedures or are established during engineering evaluation of the degraded condition. [ML13357A722, E 43 of 43, 12/16/13]

7 A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.11 track critical thermal and pressure transients for components that SQN2: Prior to 03/15/21 have been identified to have a fatigue Time Limited Aging Analysis.

B. Fatigue usage calculations that consider the effects of the reactor water environment will be developed for a set of sample reactor coolant system (RCS) components. This sample set will include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR-6260. In addition, fatigue usage calculations for reactor vessel internals (lower core plate and control rod drive (CRD) guide tube pins) will be evaluated for the effects of the reactor water environment. Fen factors will be determined as described in Section 4.3.3.

C. Fatigue usage factors for the RCS pressure boundary components will be adjusted as necessary to incorporate the effects of the Cold Overpressure Mitigation System (COMS) event (i.e., low temperature overpressurization event) and the effects of structural weld overlays.

D. Revise Fatigue Monitoring Program procedures to provide updates of the fatigue usage calculations and cycle-based fatigue waiver evaluations on an as-needed basis if an allowable cycle limit is approached, or in a case where a transient definition has been changed, unanticipated new thermal events are discovered, or the geometry of components have been modified.

E. Revise Fatigue Monitoring Program procedures to track the tensioning cycles for the reactor coolant pump hydraulic studs.

E 7 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 03/17/20 B.1.12 inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 03/15/21 degradation such as cracking, spalling, or loss of material caused by freeze thaw, chemical attack, or reaction with aggregates.

B. Revise Fire Protection Program procedures to provide acceptance criteria of no significant indications of concrete cracking, spalling, and loss of material of fire barrier walls, ceilings, and floors and in other fire barrier materials.

9 Implement the Fire Water System Program (FWSP) as described in SQN1: Prior to 03/17/20 B.1.13 LRA Section B.1.13. SQN2: Prior to 03/15/21 A. [Blank]

B. [Blank]

C. Revise FWSP procedures to ensure sprinkler heads are tested in accordance with NFPA 25 (2011 Edition), Section 5.3.1 [3.0.3-1 Request 4a]

D. [Blank]

E. Revise FWSP procedures to include acceptance criteria for periodic visual inspection of fire water system internals for corrosion, minimum wall thickness, and the absence of biofouling in the sprinkler system that could cause corrosion in the sprinklers.

F. [Blank]

G. Revise FWSP procedures to include periodically remove a representative sample of components, such as sprinkler heads or couplings, within five years prior to the PEO, and every five years during the PEO, to perform a visual internal inspection of the dry fire water system piping for evidence of corrosion, and loss of wall thickness, and foreign material that may result in flow blockage using the methodology described in NFPA-25 Section 14.2.1.

The acceptance criteria shall be no debris (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Any signs of abnormal corrosion or blockage will be removed, its source determined and corrected, and entered into the CAP. Due dates:

SQN1: within five years prior to 03/17/20, and every five years during the PEO SQN2: within five years prior to 03/15/21, and every five years during the PEO [ML14113A208 pg E-1-6 due dates]

[3.0.3-1, Req 4a.d, i to vi, ML13357A722, E 11], [ML14057A808, 3.0.3-1.4b, E-1 p25]

E 8 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (9) H. Revise FWSP procedures to perform an obstruction evaluation in accordance with NFPA-25 (2011 Edition), Section 14.3.1.

I. Revise FWSP procedures to conduct follow-up volumetric examinations if internal visual inspections detect surface irregularities that could be indicative of wall loss below nominal pipe wall thickness.

J. Revise FWSP procedures to annually inspect the fire water storage tank exterior painted surface for signs of degradation. If degradation is identified, conduct follow-up volumetric examinations to ensure wall thickness is equal to or exceeds nominal wall thickness.

The fire water storage tanks will be inspected in accordance with NFPA-25 (2011 Edition) requirements.

K. Revise FWSP procedures to include a fire water storage tank interior inspection every five years that includes inspections for signs of pitting, spalling, rot, waste material and debris, and aquatic growth.

Include in the revision direction to perform fire water storage tank interior coating testing, if any degradation is identified, in accordance with ASTM D 3359 or equivalent, a dry film thickness test at random locations to determine overall coating thickness; and a wet sponge test to detect pinholes, cracks or other compromises of the coating. If there is evidence of pitting or corrosion ensure the FWSP procedures direct performance of an examination to determine wall and bottom thickness.

L. [Blank]

M. Revise FWSP procedures to perform an annual spray head discharge pattern tests from all open spray nozzles to ensure that patterns are not impeded by plugged nozzles, to ensure that nozzles are correctly positioned, and to ensure that obstructions do not prevent discharge patterns from wetting surfaces to be protected.

Where the nature of the protected critical equipment or property is such that water cannot be discharged, the nozzles shall be inspected for proper orientation and the system tested with air, smoke or some other medium to ensure that the nozzles are not obstructed.

Ensure that the dry piping is unobstructed downstream of deluge valves protecting indoor areas containing critical equipment by flow testing with air, smoke or other medium from deluge valve through the sprinkler heads.

Based on the trip testing of the deluge valves without flow through the downstream piping and sprinkler heads, additional testing in the RCA or areas containing critical equipment is not warranted due to the addition of risk-significant activities and the production of additional radwaste. [3.0.3-1.4a, ML13357A722, E 14 of 43, 12/16/13]

E 9 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (9) N. Revise FWSP procedures to perform an internal inspection of the accessible piping associated with the strainer inspections for corrosion and foreign material that may cause blockage. Document any abnormal corrosion or foreign material in the CAP. [3.0.3-1, Request 4a, ML13357A722, E 15 of 43, 12/16/13]

O. Revise FWSP procedures to perform 25 main drain tests every 18-months with at least one main drain test performed in each of the following buildings: (1) control building, (2) auxiliary building, (3) turbine building, (4) diesel generator building and (5) ERCW building.

The results of the main drain tests from the three 18-month inspection intervals will be evaluated to determine if the NFPA 25 (2014 Edition) main drain test guidance can be applied to the number of main drain tests performed (.i.e., Section 13.2.5, "A main drain test shall be conducted annually for each water supply lead-in to a building water-based fire protection system to determine whether there has been a change in the condition of the water supply" and Section 13.2.5.1 "Where the lead-in to a building supplies a header or manifold serving multiple systems, a single main drain test shall be performed.")

Any flow blockage or abnormal discharge identified during flow testing or any change in delta pressure during the main drain testing greater than 10% at a specific location is entered into the CAP.

Flow or main drain testing increases risk due to the potential for water contacting critical equipment in the area, and main drain testing in the RCAs increases the amount of liquid radwaste. Therefore, SQN will not perform main drain tests on every standpipe with an automatic water supply or on every system riser. [3.0.3-1, Request 4a, ML13357A722, E 15 of 43, 12/16/13]

P. Revise FWSP procedures to perform One of the following inspection methods for those sections of dry piping described in NRC Information Notice (IN) 2013-06, where drainage is not occurring, to ensure there is no flow blockage in each five-year interval beginning with the five-year period before the PEO:

(a) Perform a flow test or flush sufficient to detect potential flow blockage.

(b) Remove sprinkler heads or couplings in the areas that do not drain and perform a 100% visual internal inspection to verify there are no signs of abnormal corrosion (wall thickness loss) or blockage.

If option (a) is chosen, controls will be established to ensure potential blockage is not moved to another part of the system where it may be undetected.

In each five-year interval during the PEO, 20% of the length of piping segments that cannot be drained or piping segments that allow water to collect will be subjected to UT wall thickness examination. The piping examined during each inspection E 10 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (9) interval will be piping that was not previously examined. [9.P is added ML14057A808, E-1 p23, 3.0.3-1.4b] [9.P(c) is deleted in ML14197A267 pg E 5]

If the results of a 100% internal visual inspection are acceptable, and the segment is not subsequently wetted, no further augmented tests or inspections will be performed. (3.0.3-1-3 Request 4c, ML14197A267 pg E 5) 10 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQN1: Prior to 03/17/20 B.1.14 to implement NSAC-202L guidance for examination of components SQN2: Prior to 03/15/21 upstream of piping surfaces where significant wear is detected.

B. Revise FAC Program procedures to implement the guidance in LR-ISG-2012-01, which will include a susceptibility review based on internal operating experience, external operating experience, EPRI TR-1011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves. [B.1.14-1 and B.1.38-1]

11 Revise Flux Thimble Tube Inspection Program procedures to SQN1: Prior to 03/17/20 B.1.15 include a requirement to address if the predictive trending projects SQN2: Prior to 03/15/21 that a tube will exceed 80% wall wear prior to the next planned inspection, then initiate a Service Request (SR) to define actions (i.e.,

plugging, repositioning, replacement, evaluations, etc.) required to ensure that the projected wall wear does not exceed 80%. If any tube is found to be >80% through wall wear, then initiate a Service Request (SR) to evaluate the predictive methodology used and modify as required to define corrective actions (i.e., plugging, repositioning, replacement, etc).

E 11 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 03/17/20 B.1.17 that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 03/15/21 loss of material, loose or missing nuts, and cracking of concrete around the anchor bolts.

B. Revise ISI - IWF Program procedures to include the following corrective action guidance.

When an indication is identified on a component support exceeding the acceptance criteria of IWF-3400, but an evaluation concludes the support is acceptable for service, the program shall require examination of additional similar/adjacent supports per IWF-2430 unless the evaluation of the identified condition against similar/adjacent supports concludes that it would not adversely affect the design function of similar adjacent supports. This evaluation will be performed regardless of whether the program owner chooses to perform corrective measures to restore the component to its original design condition, per IWF-3112.3(b) or IWF-3122.3(b). [ML13190A276. E1-37of79, 7/1/13]

13 Inspection of Overhead Heavy Load and Light Load (Related to SQN1: Prior to 03/17/20 B.1.18 Refueling) Handling Systems: SQN2: Prior to 03/15/21 A. Revise program procedures to specify the inspection scope will include monitoring of rails in the rail system for wear; monitoring structural components of the bridge, trolley and hoists for the aging effect of deformation, cracking, and loss of material due to corrosion; and monitoring structural connections/bolting for loose or missing bolts, nuts, pins or rivets and any other conditions indicative of loss of bolting integrity.

B. Revise program procedures to include the inspection and inspection frequency requirements of ASME B30.2.

C. Revise program procedures to clarify that the acceptance criteria will include requirements for evaluation in accordance with ASME B30.2 of significant loss of material for structural components and structural bolts and significant wear of rail in the rail system.

D. Revise program procedures to clarify that the acceptance criteria and maintenance and repair activities use the guidance provided in ASME B30.2 14 A. Implement the Internal Surfaces in Miscellaneous Piping and SQN1: Prior to 03/17/20 B.1.19 Ducting Components Program as described in LRA Section B.1.19. SQN2: Prior to 03/15/21 B. Specific, measurable, actionable/attainable and relevant acceptance criteria are established in the maintenance and surveillance procedures or are established during engineering evaluation of the degraded condition. [ML13357A722, E 43 of 43, 12/16/13]

E 12 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Prior to 03/17/20 B.1.21 described in LRA Section B.1.21. SQN2: Prior to 03/15/21 16 A. Revise Neutron Absorbing Material Monitoring Program SQN1: Prior to 03/17/20 B.1.22 procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 03/15/21 the ten years prior to the PEO and at least every ten years thereafter based on initial testing to determine possible changes in boron-10 areal density.

B. Revise Neutron Absorbing Material Monitoring Program procedures to relate physical measurements of Boral coupons to the need to perform additional testing.

C. Revise Neutron Absorbing Material Monitoring Program procedures to perform trending of coupon testing results to determine the rate of degradation and to take action as needed to maintain the intended function of the Boral.

17 Implement the Non-EQ Cable Connections Program as described SQN1: Prior to 03/17/20 B.1.24 in LRA Section B.1.24 SQN2: Prior to 03/15/21 18 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) SQN1: Prior to 03/17/20 B.1.25 Program as described in LRA Section B.1.25 SQN2: Prior to 03/15/21 A. B.1.25.1a [ML13296A017, E-1-12of25, 10/21/13] 18.A.1 & A.2 are completed. See Cnl 1. [Blank]

105, Enc 1, p14 of 16.

2. [Blank]

18.A.3:

3. Prior to the PEO, the license renewal commitment for the Non-EQ SQN1: Prior to 03/17/20 Inaccessible Power Cables (400 V to 35 kV) Program will SQN2: Prior to 03/15/21 establish diagnostic testing activities on all inaccessible power cables in the 400 V to 35kV range that are in the scope of license renewal and subject to aging management review.

18.A4: completed, See

4. Revise the manhole inspection procedures to specify the Cnl-14-221, cover letter maximum allowable water level to preclude cable submergence in the manhole. If the inspection identifies submergence of inaccessible power cable for more than a few days, the condition will be documented and evaluated in the SQN CAP. The evaluation will consider results of the most recent diagnostic testing, insulation type, submergence level, voltage level, energization cycle (usage), and various other inputs to determine whether the cables remain capable of performing their intended current licensing basis function. [Blank]

5. Once 18.A.1, 2, and 4 are fully completed, these commitments can be deleted from this list or the UFSAR.

E 13 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 19 Implement the Non-EQ Instrumentation Circuits Test Review SQN1: Prior to 03/17/20 B.1.26 Program as described in LRA Section B.1.26. SQN2: Prior to 03/15/21 20 Implement the Non-EQ Insulated Cables and Connections SQN1: Prior to 03/17/20 B.1.27 Program as described in LRA Section B.1.27 SQN2: Prior to 03/15/21 21 A. Revise Oil Analysis Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.28 maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 03/15/21 acceptable limits through periodic sampling in accordance with industry standards, manufacturer's recommendations and plant-specific operating experience.

B. Revise Oil Analysis Program procedures to trend oil contaminant levels and initiate a problem evaluation report if contaminants exceed alert levels or limits in the 161-kV oil-filled cable system.

22 Implement the One-Time Inspection Program as described in LRA SQN1: Prior to 03/17/20 B.1.29 Section B.1.29. SQN2: Prior to 03/15/21 23 Implement the One-Time Inspection - Small Bore Piping Program SQN1: Prior to 03/17/20 B.1.30 as described in LRA Section B.1.30 SQN2: Prior to 03/15/21 24 A. Revise Periodic Surveillance and Preventive Maintenance 24.A&C B.1.31 Program procedures as necessary to include all activities described SQN1: Prior to 03/17/20 in the table provided in the LRA Section B.1.31 program description. SQN2: Prior to 03/15/21 B. For in-scope components that have internal Service Level III or 24.B Other coatings, initial inspections will begin no later than the last SQN1: RFO Prior to scheduled refueling outage prior to the PEO. Subsequent inspections 09/17/20 will be performed based on the initial inspection results. [3.0.3-1, Request 3, ML13312A005, pages E 2,5,7 of 51] SQN2: RFO Prior to 09/15/21 C. Revise Periodic Surveillance and Preventive Maintenance Program procedures to perform a minimum of five MIC degradation inspections per year until the rate of MIC occurrences no longer meets the criteria for recurring internal corrosion. [cnl-14-105, E1p11]

If more than one MIC-caused leak or a wall thickness less than Tmin is identified in the yearly inspection period, an additional five MIC inspections over the following 12 month period will be performed for each MIC leak or finding of wall thickness less than Tmin. The total number of inspections need not exceed a total of 25 MIC inspections per year. [ML14057A808, E-1 p8, 3.0.3-1-3a]

Prior to the period of extended operation, select a method (or methods) from available technologies for inspecting internal surfaces of buried piping (System 26/HPFP Firewater and 67/ERCW) that provides suitable indication of piping wall thickness for a representative set of buried piping locations to supplement the set of selected inspection locations E 14 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (24) [3.0.3-1, Req 1a, ML13357A722, E 4 of 43, 12/16/13]

[3.0.3-1 Req 1, ML13294A462, E 6 of 13, 10/17/13] [Moved 9.F to 24.C in ML14057A808, E-1 p13,29]

D.

1. Prior to the PEO, perform a visual inspection of a 50%

sample of the coated piping in each of the following coated piping systems or an area equivalent to the entire inside surface of 73 1-foot piping segments for each combination of type of coating, substrate material, and environment.

Inspection location selection will be based on an evaluation of the effect of a coating failure on component intended functions, potential problems identified during prior inspections, and service life history. Visually inspect the surface condition of the coated components to manage loss of coating integrity due to cracking, debonding, delamination, peeling, flaking, and blistering. In addition, if coatings are credited for corrosion prevention, the base material (in the vicinity of delamination, peeling, or blisters where base metal has been exposed) will be inspected to determine if corrosion has occurred.

Piping:

i. High pressure fire protection (cement-lined piping) ii. Essential raw cooling water (where Belzona applied)

2. With the exception of the EDG 7-day fuel oil tanks, perform subsequent inspections of coatings based on the following.

i. If no flaking, debonding, peeling, delamination, blisters, or rusting are observed, and any cracking and flaking has been found acceptable, subsequent inspections will be performed at least once every six years. If the coating is inspected on one train and no indications are found, the same coating on the redundant train would not be inspected during that inspection interval.

ii. If the inspection results do not meet (i), yet a coating specialist has determined that no remediation is required, then subsequent inspections will be conducted every other refueling outage.

iii. If coating degradation is observed that requires newly installed coatings, subsequent inspections will occur during each of the next two refueling outage intervals to establish a performance trend on the coating.

EDG 7-day fuel oil tanks coating inspection:

Subsequent coating inspections for the EDG 7-day fuel oil tanks will be at the same 10 year interval as TS Surveillance Requirement 4.8.1.1.2.f. If any applied Belzona coating on the interior of the fuel oil tanks is peeling, delaminating, or blistering, then the condition will be repaired and entered into the CAP.

Given the favorable SQN experience with the current Belzona repairs, it is justifiable to repair the existing coating applied to localized pits with Belzona and not inspect the coating for another 10 years, provided a detached Belzona engineering transportability evaluation has determined that the amount of E 15 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (24) Belzona applied will not migrate from the EDG 7-day tank to the day-tank. The evaluation will consider Belzonas 2.5 to 3 times higher specific gravity than diesel fuel, potential size of loosened Belzona particles, surface area and depth of the applied Belzona, diesel fuel fluid velocity in the immediate area of the applied Belzona, proximity of the repaired area to the suction line, and other factors.

The application of Belzona to repair additional localized pitting in the 7-day EDG fuel oil tanks in the future will be installed per vendor specifications. An engineering evaluation will be performed to ensure that that additional Belzona cannot be transferable out of the tank during the interval between tank inspections and to determine if the interval of inspections should meet the more frequent inspection guidelines of LR-ISG-2013-01, or the NRC approved TS Surveillance Requirement of 10 years.

The engineering transportability evaluation will consider factors such as specific gravity, size, depth, surface area, and fluid velocity in the evaluation. [ML14057A808, E-1 p7]

E. Prior to the PEO, perform a visual inspection of the following coated tanks and heat exchangers. Visually inspect the surface condition of the coated components to manage loss of coating integrity due to cracking, debonding, delamination, peeling, flaking, and blistering.

Tanks

i. Cask decontamination collector (where 2 coats Red Lead in oil ,

Fed SPEC TTP-85 Type II applied) ii. Safety injection lube oil reservoir (where 0.006 inch plastic coating applied) iii. Pressurizer relief (where Ambercoat 55 applied) iv. EDG 7-day fuel oil (where Belzona applied)

v. Condensate storage tank Heat Exchangers

i. Electric board room chiller package (where Belzona applied) ii. Incore instrument room water chiller package B (where Belzona applied) [ML14057A808, E-1 p6]

F. Any indication or relevant condition of degradation detected is evaluated.

Include the following acceptance criteria for loss of coatings integrity: For any indication or relevant condition of coating degradation, the indication or relevant condition is evaluated for loss of coatings integrity. [ ML14063A542, E-1 p2]

(1) Peeling and delamination are not permitted, (2) Cracking is not permitted if accompanied by delamination or loss of adhesion, and (3) Blisters are limited to intact blisters that are completely surrounded by sound coating bonded to the surface.

Corrective Action: If delamination, peeling, or blisters are E 16 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM detected, follow-up physical testing will be performed where physically possible (i.e., sufficient room to conduct testing) on at least three locations. The testing will consist of destructive or nondestructive adhesion testing using ASTM International standards endorsed in Regulatory Guide 1.54. [ML14057A808, E-1 p6]

G.

1. Coating inspections are performed by individuals certified to ANSI N45.2.6, "Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants," and that subsequent evaluation of inspection findings is conducted by a nuclear coatings subject matter expert qualified in accordance with ASTM D 7108-05, "Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist."

2. An individual knowledgeable and experienced in nuclear coatings work will prepare a coating report that includes a list of locations identified with coating deterioration including, where possible, photographs indexed to inspection location, and a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where coating repair can be postponed to the next inspection.

[ML14057A808, E-1 p6]

25 A. Revise Protective Coating Program procedures to clarify that SQN1: Prior to 03/17/20 B.1.32 detection of aging effects will include inspection of coatings near SQN2: Prior to 03/15/21 sumps or screens associated with the emergency core cooling system.

B. Revise Protective Coating Program procedures to clarify that instruments and equipment needed for inspection may include, but not be limited to, flashlights, spotlights, marker pen, mirror, measuring tape, magnifier, binoculars, camera with or without wide-angle lens, and self-sealing polyethylene sample bags.

C. Revise Protective Coating Program procedures to clarify that the last two performance monitoring reports pertaining to the coating systems will be reviewed prior to the inspection or monitoring process.

26 A. Revise Reactor Head Closure Studs Program procedures to SQN1: Prior to 03/17/20 B.1.33 ensure that replacement studs are fabricated from bolting material SQN2: Prior to 03/15/21 with actual measured yield strength less than 150 ksi.

B. Revise Reactor Head Closure Studs Program procedures to exclude the use of molybdenum disulfide (MoS2) on the reactor vessel closure studs and to refer to Reg. Guide 1.65, Rev1.

E 17 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 27 A. Revise Reactor Vessel Internals Program procedures to 27.A & B B.1.34 perform direct measurement of Unit 1 304 SS hold down spring SQN1: Within three U1 height within three cycles of the beginning of the period of extended refuel cycles of the date operation. If the first set of measurements is not sufficient to 09/17/20 determine life, spring height measurements must be taken during the next two outages, in order to extrapolate the expected spring height SQN2: Not Applicable to 60 years. (ML13324A982, 11/15/13, Enc 1, pages 24-25)

B. Revise Reactor Vessel Internals Program procedures to include preload acceptance criteria for the Type 304 stainless steel hold-down springs in Unit 1.

C. Continued monitoring of industry operating experience in the area 27.C SQN 1&2: Within of RVI Clervis Bolt will be performed and the program will be three U1 refuel cycles of modified, if necessary. [ML14057A808, E-1 p35, B.1.34-8] the date 09/17/20 27.D is completed .

D. [Blank]

See B.1.34-9b in Cnl-14-105, Enc 1, pg1 E. Revise Reactor Vessel Internals Program procedures to identify 27.E the observation of cracking in the lower core barrel girth weld as the SQN1: Prior to 03/17/20 primary trigger for the EVT-1 expansion inspection of the upper core SQN2: Prior to 03/15/21 plate. [B.1.34-9d (follow-up) in Cnl-14-221, Enc 1.

28 A. Revise Reactor Vessel Surveillance Program procedures to SQN1: Prior to 03/17/20 B.1.35 consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 03/15/21 and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by just considering the reactor vessel beltline materials.

B. Revise Reactor Vessel Surveillance Program procedures to incorporate an NRC-approved schedule for capsule withdrawals to meet ASTM-E185-82 requirements, including the possibility of operation beyond 60 years (refer to the TVA Letter to NRC, Sequoyah Reactor Pressure Vessel Surveillance Capsule Withdrawal Schedule Revision Due to License Renewal Amendment, dated 01/10/13, ML13032A251; NRC FSER approved on 09/27/13, ML13240A320)

C. Revise Reactor Vessel Surveillance Program procedures to withdraw and test a standby capsule to cover the peak fluence expected at the end of the PEO.

29 Implement the Selective Leaching Program as described in LRA SQN1: Prior to 03/17/20 B.1.37 Section B.1.37. SQN2: Prior to 03/15/21 30 Revise Steam Generator Integrity Program procedures to ensure SQN1: Prior to 03/17/20 B.1.39 that corrosion resistant materials are used for replacement steam SQN2: Prior to 03/15/21 generator tube plugs.

E 18 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 31 A. Revise Structures Monitoring Program (SMP) procedures to SQN1: Prior to 03/17/20 B.1.40 include the following in-scope structures: SQN2: Prior to 03/15/21 Carbon dioxide building Condensate storage tanks' (CSTs) foundations and pipe trench East steam valve room Units 1 & 2 Essential raw cooling water (ERCW) pumping station High pressure fire protection (HPFP) pump house and water storage tanks' foundations Radiation monitoring station (or particulate iodine and noble gas station) Units 1 & 2 Service building Skimmer wall (Cell No. 12)

Transformer and switchyard support structures and foundations B. Revise SMP procedures to specify the following list of in-scope structures are included in the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program (Section B.1.36):

Condenser cooling water (CCW) pumping station (also known as intake pumping station) and retaining walls CCW pumping station intake channel ERCW discharge box ERCW protective dike ERCW pumping station and access cells Skimmer wall, skimmer wall Dike A and underwater dam C. Revise SMP procedures to include the following in-scope structural components and commodities:

Anchor bolts Anchorage/embedments (e.g., plates, channels, unistrut, angles, other structural shapes)

Beams, columns and base plates (steel)

Beams, columns, floor slabs and interior walls (concrete)

Beams, columns, floor slabs and interior walls (reactor cavity and primary shield walls; pressurizer and reactor coolant pump compartments; refueling canal, steam generator compartments; crane wall and missile shield slabs and barriers)

Building concrete at locations of expansion and grouted anchors; grout pads for support base plates Cable tray Cable tunnel Canal gate bulkhead Compressible joints and seals Concrete cover for the rock walls of approach channel Concrete shield blocks Conduit Control rod drive missile shield Control room ceiling support system Curbs Discharge box and foundation E 19 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) Doors (including air locks and bulkhead doors)

Duct banks Earthen embankment Equipment pads/foundations Explosion bolts (E. G. Smith aluminum bolts)

Exterior above and below grade; foundation (concrete)

Exterior concrete slabs (missile barrier) and concrete caps Exterior walls: above and below grade (concrete)

Foundations: building, electrical components, switchyard, transformers, circuit breakers, tanks, etc.

Ice baskets Ice baskets lattice support frames Ice condenser support floor (concrete)

Insulation (fiberglass, calcium silicate)

Intermediate deck and top deck of ice condenser Kick plates and curbs (steel - inside steel containment vessel)

Lower inlet doors (inside steel containment vessel)

Lower support structure structural steel: beams, columns, plates (inside steel containment vessel)

Manholes and handholes Manways, hatches, manhole covers, and hatch covers (concrete)

Manways, hatches, manhole covers, and hatch covers (steel)

Masonry walls Metal siding Miscellaneous steel (decking, grating, handrails, ladders, platforms, enclosure plates, stairs, vents and louvers, framing steel, etc.)

Missile barriers/shields (concrete)

Missile barriers/shields (steel)

Monorails Penetration seals Penetration seals (steel end caps)

Penetration sleeves (mechanical and electrical not penetrating primary containment boundary)

Personnel access doors, equipment access floor hatch and escape hatches Piles Pipe tunnel Precast bulkheads Pressure relief or blowout panels Racks, panels, cabinets and enclosures for electrical equipment and instrumentation Riprap Rock embankment Roof or floor decking Roof membranes Roof slabs RWST rainwater diversion skirt E 20 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) RWST storage basin Seals and gaskets (doors, manways and hatches)

Seismic/expansion joint Shield building concrete foundation, wall, tension ring beam and dome: interior, exterior above and below grade Steel liner plate Steel sheet piles Structural bolting Sumps (concrete)

Sump liners (steel)

Sump screens Support members; welds; bolted connections; support anchorages to building structure (e.g., non-ASME piping and components supports, conduit supports, cable tray supports, HVAC duct supports, instrument tubing supports, tube track supports, pipe whip restraints, jet impingement shields, masonry walls, racks, panels, cabinets and enclosures for electrical equipment and instrumentation)

Support pedestals (concrete)

Transmission, angle and pull-off towers Trash racks Trash racks associated structural support framing Traveling screen casing and associated structural support framing Trenches (concrete)

Tube track Turning vanes Vibration isolators D. Revise SMP procedures to include periodic sampling and chemical analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of at least every five years.

E. Revise Masonry Wall Program procedures to specify masonry walls located in the following in-scope structures are in the scope of the Masonry Wall Program:

Auxiliary building Reactor building Units 1 & 2 Control bay ERCW pumping station HPFP pump house Turbine building F. Revise SMP procedures to include the following parameters to be monitored or inspected:

Requirements for concrete structures based on ACI 349-3R and ASCE 11 and include monitoring the surface condition for loss of material, loss of bond, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) Loose or missing nuts for structural bolting.

Monitoring gaps between the structural steel supports and masonry walls that could potentially affect wall qualification.

Monitor the surface condition of insulation (fiberglass, calcium silicate) to identify exposure to moisture that can cause loss of insulation effectiveness.

G. Revise SMP procedures to include the following components to be monitored for the associated parameters:

Anchors/fasteners (nuts and bolts) will be monitored for loose or missing nuts and/or bolts, and cracking of concrete around the anchor bolts.

Elastomeric vibration isolators and structural sealants will be monitored for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening).

[moved to the last bullet on 31.F ]

H. Revise SMP procedures to include the following for detection of aging effects:

Inspection of structural bolting for loose or missing nuts.

Inspection of anchor bolts for loose or missing nuts and/or bolts, and cracking of concrete around the anchor bolts.

Inspection of elastomeric material for cracking, loss of material, loss of sealing, and change in material properties (e.g.,

hardening), and supplement inspection by feel or touch to detect hardening if the intended function of the elastomeric material is suspect. Include instructions to augment the visual examination of elastomeric material with physical manipulation of at least ten percent of available surface area.

Opportunistic inspections when normally inaccessible areas (e.g., high radiation areas, below grade concrete walls or foundations, buried or submerged structures) become accessible due to required plant activities. Additionally, inspections will be performed of inaccessible areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant degradation is occurring.

Inspection of submerged structures at least once every five years.

Inspections of water control structures should be conducted under the direction of qualified personnel experienced in the investigation, design, construction, and operation of these types of facilities.

Inspections of water control structures shall be performed on an interval not to exceed five years.

Perform special inspections of water control structures immediately (within 30 days) following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, and intense local rainfalls.

Insulation (fiberglass, calcium silicate) will be monitored for loss of material and change in material properties due to E 22 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) potential exposure to moisture that can cause loss of insulation effectiveness.

Revise SMP procedures to clarify that detection of aging effects will include the following.

Qualifications of personnel conducting the inspections or testing and evaluation of structures and structural components meet the guidance in Chapter 7 of ACI 349.3R.

I. Revise SMP procedures to prescribe quantitative acceptance criteria based on the quantitative acceptance criteria of ACI 349.3R and information provided in industry codes, standards, and guidelines including ACI 318, ANSI/ASCE 11 and relevant AISC specifications.

Industry and plant-specific operating experience will also be considered in the development of the acceptance criteria.

J. [Blank]

K. Revise SMP procedures to include the following acceptance criteria for insulation (calcium silicate and fiberglass)

No moisture or surface irregularities that indicate exposure to moisture.

L. Revise SMP procedures to include the following preventive actions.

Specify protected storage requirements for high-strength fastener components (specifically ASTM A325 and A490 bolting).

Storage of these fastener components shall include:

1. Maintaining fastener components in closed containers to protect from dirt and corrosion;

2. Storage of the closed containers in a protected shelter;

3. Removal of fastener components from protected storage only as necessary; and

4. Prompt return of any unused fastener components to protected storage.

M. RAI B.1.40-4a Response (Turbine Building wall crack):

1. SQN will map and trend the crack in the condenser pit north wall.

2. SQN will test water inleakage samples from the turbine building condenser pit walls and floor slab for minerals and iron content to assess the effect of the water inleakage on the concrete and the reinforcing steel.

3. SQN will test concrete core samples removed from the turbine building condenser pit north wall with a minimum of one core sample in the area of the crack. The core samples will be tested for compressive strength and modulus of elasticity and subjected to petrographic examination.

4. The results of the tests and SMP inspections will be used to determine further corrective actions, including, but not limited to, E 23 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) more frequent inspections, sampling and analysis of the inleakage water for minerals and iron, and evaluation of the affected area using evaluation criteria and acceptance criteria of ACI 349.3R. [Outcome of the Nrc 01/14/14 telecom]

5. Commitment #31.M will be implemented before the PEO for SQN Units 1 and 2. . [ML13296A017, E-1-10of25, 10/21/13, for 31.M.1 to 5]

32 Implement the Thermal Aging Embrittlement of Cast Austenitic B.1.41 Stainless Steel (CASS) as described in LRA Section B.1.41 A. B.1.41-4a: For those CASS components with delta ferrite content 32.A

> 25%, additional analysis will be performed using plant-specific SQN1: Prior to 03/17/20 materials data and best available fracture toughness curves. SQN2: Prior to 03/15/21 (B.1.41-4a, ML13225A387, E 19 of 25)

B. B.1.41-4b: For CASS materials with estimated delta ferrite > 20% 32.B that have been determined susceptible to thermal aging, a flaw SQN1: Prior to 09/17/18 tolerance analysis may be necessary. If a flaw tolerance analysis will SQN2: Prior to 09/15/19 be required for the susceptible CASS components, the SQN-specific flaw tolerance method will be submitted to the NRC for review and approval at least two years prior to the PEO; unless ASME has approved the flaw tolerance analysis methodology that SQN will use.

(SQN1: Prior to 09/17/18 SQN2: Prior to 09/15/19)

[ML13357A722, E 1 of 43, 12/16/13]

33 A. Revise Water Chemistry Control - Closed Treated Water SQN1: Prior to 03/17/20 B.1.42 Systems Program procedures to provide a corrosion inhibitor for the SQN2: Prior to 03/15/21 following chilled water subsystems in accordance with industry guidelines and vendor recommendations:

Auxiliary building cooling Incore Chiller 1A, 1B, 2A, & 2B 6.9 kV Shutdown Board Room A & B B. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to conduct inspections whenever a boundary is opened for the following systems:

Standby diesel generator jacket water subsystem Component cooling system Glycol cooling loop system High pressure fire protection diesel jacket water system Chilled water portion of miscellaneous HVAC systems (i.e.,

auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kV Shutdown Board Room A & B)

C. Revise Water Chemistry Control-Closed Treated Water Systems Program procedures to state these inspections will be conducted in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that are capable of detecting corrosion or cracking.

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (33) D. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to perform sampling and analysis of the glycol cooling system per industry standards and in no case greater than quarterly unless justified with an additional analysis.

E. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to inspect a representative sample of piping and components at a frequency of once every ten years for the following systems:

Standby diesel generator jacket water subsystem Component cooling system Glycol cooling loop system High pressure fire protection diesel jacket water system Chilled water portion of miscellaneous HVAC systems (i.e.,

auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kV Shutdown Board Room A & B)

F. Components inspected will be those with the highest likelihood of corrosion or cracking. A representative sample is 20% of the population (defined as components having the same material, environment, and aging effect combination) with a maximum of 25 components. These inspections will be in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that ensure the capability of detecting corrosion or cracking.

34 Revise Containment Leak Rate Program procedures to require SQN1: Prior to 03/17/20 B.1.7 venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 03/15/21 containment atmosphere prior to the CILRT and resealing the vent path after the CILRT to prevent moisture intrusion during plant operation.

35 A. From RAI B.1.6-1 Response: Modify the configuration of the SQN 35.A: B.1.6 Unit 1 test connection access boxes to prevent moisture intrusion to SQN1: Prior to 03/17/20 the leak test channels. Prior to installing this modification, TVA will SQN2: Not Applicable perform remote visual examinations inside the leak test channels by inserting a borescope video probe through the test connection tubing.

B. From B.1.6-1b Response: To monitor the condition of the access 35. B & C:

boxes and associated materials, develop and implement an SQN1: Prior to 03/17/20 instruction/procedure to perform visual examinations of all accessible SQN2: Prior to 03/15/21 surfaces, including the access box surfaces, cover plate, welds, and gasket sealing surfaces of the access boxes on each unit every other refueling outage with the gasketed access box lid removed.

C. From B.1.6-2b Response: develop and implement an instruction/procedure to continue volumetric examinations where the SCV domes were cut at the frequency of once every five years until the coatings are reinstalled at these locations.

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 36 A. Revise Inservice Inspection Program procedures to include a SQN1: Prior to 03/17/20 B.1.16 supplemental inspection of Class 1 CASS piping components that SQN2: Prior to 03/15/21 do not meet the materials selection criteria of NUREG-0313, Revision 2, with regard to ferrite and carbon content. An inspection techniques qualified by ASME or EPRI will be used to monitor cracking.

Inspections will be conducted on a sampling basis. The extent of sampling will be based on the established method of inspection and industry operating experience and practices when the program is implemented, and will include components determined to be limiting from the standpoint of applied stress, operating time and environmental considerations. (RAI 3.1.2.2.6.2-1)

B. Revise the Inservice Inspection Program procedures to perform an augmented visual inspection of the Unit 1 and Unit 2 CRDM thermal sleeves and a wall thickness measurement of the six thermal sleeves exhibiting the greatest amount of wear. The results of the augmented inspection should be used to project if there is sufficient wall thickness for the PEO, or until the next inspection. (RAI B.1.23-2d)

C. Evaluate industry operating experience related to CRDM housing penetration wear and initiatives to measure CRDM housing penetration wear and resulting wall thickness. Upon successful demonstration of a wear depth measurement process, SQN will revise Inservice Inspection Program procedures to use the demonstrated process at accessible locations to measure depth of wear on the CRDM housing penetration wall associated with contact with the CRDM thermal sleeve centering pads. (RAI B.1.23-2c; Cnl-14-105, Enc 1, A & B.1.16, Inservice Inspection Program, rev 17)

D. Revise Inservice Inspection Program procedure to perform an examination of the accessible CRDM housing penetrations to determine the amount of wear in the area of the thermal sleeve centering pads for Units 1 and 2. The accessible locations consist of the centermost CRDM housing penetrations 1 through 5. (RAI B.1.23-2c)

E. Revise Inservice Inspection Program procedure to estimate the wall thickness of the accessible CRDM housing penetration wear in the area of the thermal sleeve centering tabs at the end of the next RVH inspection interval and compare the projected wall thickness to the thickness used in Sequoyah design basis analyses to demonstrate validity of the analyses. (RAI B.1.23-2c; Cnl-14-105, Enc 1, A & B.1.16, Inservice Inspection Program, rev 17)

F. Revise Inservice Inspection Program procedure to monitor the wear of the accessible CRDM housing penetrations in weld examination volume. (RAI B.1.23-2c)

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (36) G. TVA ASME Section XI Program procedure which defines the Class 1 components subject to examination will be revised to specifically require a visual examination method VT-3 of the clevis bolts, dowel pins and tack welds as well as the six core support pads.

[ML14063A542, E-1 p4, B.1.34-8a]

H. Revise SQNs Category B-N-3 inspection procedure to reference the September 22, 2014, NRC RAI B.1.34-9c and the SQNs response (ML14254A204 and CNL-14-181) to identify that the inspection of the accessible regions the upper core plate lower surface (core support structure components, VT-3 inspection below the upper core plate to determine the general mechanical and structural condition of components) as a required License Renewal Inspection during the PEO. (CNL-14-181)

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 37 TVA will implement the Operating Experience for the AMPs in 37.A, B, D-FG: No later B.0.4 accordance with the TVA response to the RAI B.0.4-1 on than the scheduled issue 07/29/13, ML13213A027; and 10/17/13 letter, RAIs B.0.4-1a and date of the renewed A.1-1a. operating licenses for SQN Units 1 & 2.

A. Revise OE Program Procedure to include current and future (Currently February revisions to NUREG-1801, Generic Aging Lessons Learned 2015)

(GALL) Report, as a source of industry OE, and unanticipated age-related degradation or impacts to aging management activities as a screening attribute.

B. Revise the Corrective Action Procedure (CAP) Procedure to provide a screening process of corrective action documents for aging management items, the assignment of aging corrective actions to appropriate AMP owners, and consideration of the aging management trend code.

C. Revise AMP procedures as needed to provide for review and 37.C:

evaluation by AMP owners of data from inspections, tests, SQN1: Prior to 03/17/20 analyses or AMP OEs. [ML14063A542, E-1 p3] SQN2: Prior to 03/15/21 D. Revise the OE Program Procedure to provide guidance for reporting plant-specific OE on unanticipated age-related degradation or impact to aging management activities to the TVA fleet and/or INPO.

E. Revise the OE, CAP, Initial and Continuing Engineering Support Personnel Training to address age-related topics, the unanticipated degradation or impacts to the aging management activities; including periodic refresher/update training and provisions to accommodate the turnover of plant personnel, and recent AMP-related OE from INPO, the NRC, Scientech, and nuclear industry-initiated guidance documents and standards.

F. A comprehensive and holistic AMP training topic list will be developed before the date the SQN renewed operating license is scheduled to be issued.

G. TVA AMP OE Process, AMP adverse trending & evaluation in CAP, AMP Initial and Refresher Training will be fully implemented by the date the SQN renewed operating license is scheduled to be issued.

Once Commitment 37 is fully completed, Commitment 37 can be deleted from this list or the UFSAR.

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 38 A. Implement the Service Water Integrity Program (SWIP) as SQN1: Prior to 03/17/20 B.1.38 described in LRA Section B.1.38. [3.0.3-1, Requests 3, SQN2: Prior to 03/15/21 ML13312A005.E 11 of 51, 11/4/13, for 38.A to F]

B. Parameters Monitored/Inspected: Revise SWIP procedures to monitor the condition of coated surfaces in the heat exchangers credited in the response to NRC Generic Letter (GL) 89-13 response.

C. Detection of aging Effect : Revise the SWIP procedures to perform periodic visual inspections to manage loss of coating integrity due to cracking, debonding, delamination, peeling, flaking, and blistering in heat exchangers credited in the NRC Generic Letter (GL) 89-13 response.

D. Acceptance Criteria: Revise the SWIP procedures to include the following coating integrity acceptance criteria:

(1) peeling and delamination are not permitted, (2) cracking is not permitted if accompanied by delamination or loss of adhesion, and (3) blisters are limited to intact blisters that are completely surrounded by sound coating bonded to the surface.

E. Monitoring and Trending: Revise SWIP procedures to ensure an individual knowledgeable and experienced in nuclear coatings work will prepare a coating report that includes a list of locations identified with coating deterioration including, where possible, photographs indexed to inspection location, and a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where coating repair can be postponed to the next inspection.

F. Qualification: Revise SWIP procedures to ensure coating inspections are performed by individuals certified to ANSI N45.2.6, "Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants," and that subsequent evaluation of inspection findings is conducted by a nuclear coatings subject matter expert qualified in accordance with ASTM D 7108-05, "Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist."

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LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (38) G. Before the PEO, revise Service Water Integrity Program procedures to (1) Monitor the existence of fouling or clogging in ERCW stagnant/dead leg piping.

This enhancement is applicable to ERCW flow-paths that fulfill a safety-related function.

(2) Periodically place normally ERCW stagnant/dead legs in service for the purpose of flushing. Alternatively, periodically flush the normally stagnant/dead leg by temporarily/permanently installing a flushing valve (without placing the line in service).

(3) In lieu of flushing, perform periodic radiograph, demonstrated ultrasonic or visual inspections of ERCW stagnant /dead leg piping are acceptable to confirm the absence of fouling/clogging, and (4) When ERCW clogging/fouling of stagnant/dead leg piping is identified, enter findings into the corrective action program and perform an evaluation of the impact of ERCW design functions.

(Cnl-14-105, Enc 1, A&B.1.38 Service Water Integrity, rev 17) 39 Implement the Boric Acid Corrosion Program as described in LRA SQN1: Prior to 03/17/20 B.1.3 Section B.1.3. SQN2: Prior to 03/15/21 40 Implement the Environmental Qualification (EQ) Of Electric SQN1: Prior to 03/17/20 B.1.9 Components Program as described in LRA Section B.1.9. SQN2: Prior to 03/15/21 41 Implement the Masonry Wall Program as described in LRA Section SQN1: Prior to 03/17/20 B.1.20 B.1.20. SQN2: Prior to 03/15/21 42 Implement the Nickel Alloy Inspection Program as described in SQN1: Prior to 03/17/20 B.1.23 LRA Section B.1.23. SQN2: Prior to 03/15/21 43 Implement the Water Chemistry Control - Primary And Secondary SQN1: Prior to 03/17/20 B.1.43 Program as described in LRA Section B.1.43. SQN2: Prior to 03/15/21 44 Implement the RG 1.127, Inspection Of Water-Control Structures SQN1: Prior to 03/17/20 B.1.36 Associated With Nuclear Power Plants Program as described in SQN2: Prior to 03/15/21 LRA Section B.1.36.

The above table identifies the 44 SQN NRC LR commitments. Any other statements in this letter are provided for information purposes and are not considered to be regulatory commitments.

This commitment list revision supersedes all previous versions.

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